In newly discovered oil fields, oil usually will be recovered by flowing from a producing well under the naturally occurring pressure of the fluids present in the porous reservoir rocks. That naturally occurring pressure decreases as the fluids are removed. This phase of production, called primary production, recovers perhaps 5% to 20% of the oil present in the formation.
Secondary recovery methods (e.g., waterflooding) are used to recover more of the oil. In these methods, a fluid is injected into the reservoir to drive additional oil out of the rocks. Waterflooding has limitations. As the water is immiscible with oil, and as the water displaces the oil, oil remaining in the reservoir reaches a limiting value known as "the residual oil saturation" and oil no longer flows. There is a strong capillary action which tends to hold the oil in the interstices of the rocks. The amount of oil recovered by secondary techniques is usually from about 5% to 30% of the oil initially present.
In recent years, more attention has been directed to enhanced recovery or tertiary recovery techniques. While these methods are more expensive, they are justified by the increased price of crude. In general, these tertiary recovery methods are used to recover the residual oil by overcoming the capillary forces which trap oil during waterflooding. For example, it has been suggested to add surfactants to the flood to decrease the interfacial tension and thus allow oil droplets to move to producing wells.
Secondary or tertiary recovery of oil is also possible by the miscible fluid displacement process. Propane, for example, can be used, for it is fully miscible with oil. But, except in remote regions such as the Arctic, where it is impractical to pipe propane, propane is usually far too expensive to use.
Nevertheless, it is well known to use crude oil miscible solvents, such as propane, to displace crude oil through a formation. For example, see the teachings of Morse in U.S. Pat. No. 3,354,953. Morse suggests that the viscosity of the propane can be increased by the addition of kerosene. Henderson et al. teach in U.S. Pat. No. 3,330,345 the use of a slug of thickened material, such as propane, before flooding with an amphipathic solvent. Dauben et al. teach in U.S. Pat. No. 3,570,601 the recovery of oil using viscous propane, where the propane is viscosified by first dissolving a solid polymer (such as polyisobutylene) in a heavier hydrocarbon (such as heptane) and then diluting this first solution with propane to form the oil-driving bank.
In the continental United States, carbon dioxide is generally less expensive than propane. A number of carbon dioxide floods have been tried in the United States. The carbon dioxide tends to dissolve in the oil which swells with a consequent decrease in viscosity and improvement in the flow to producing wells. The carbon dioxide also extracts light hydrocarbons from the oil and this mixture of carbon dioxide and light hydrocarbons can in some cases reach a composition that will miscibly displace the oil. This carbon dioxide-rich phase characteristically has a lower viscosity than the oil and tends to finger through the formation. Early carbon dioxide breakthrough is undesirable since reservoir sweep is reduced and expensive separation procedures are required to separate and recycle the carbon dioxide. For example, the viscosity of carbon dioxide at usual reservoir pressures and temperatures is on the order of a few hundredths of a centipoise while the oil being displaced may have a viscosity in the range of from 0.1 to 100 centipoises.
An increase in the viscosity of carbon dioxide would be helpful in decreasing the mobility of the carbon dioxide, thus increasing the pressure gradient behind the frontal region which would reduce fingering and improve the reservoir sweep.
The prior art describes a number of techniques to control the mobility of carbon dioxide. These techniques are described generally in an article entitled "CO.sub.2 as Solvent for Oil Recovery" by F. M. Orr, Jr. et al. (Chemtech, August 1983, page 42, et seq.). There is the water-alternating-with-gas process where slugs of carbon dioxide are injected alternatively with slugs of water. Also studied was the use of polyxers to reduce carbon dioxide mobility. The F. M. Orr, Jr. et al. paper describes studies by New Mexico Petroleum Recovery Research Center that indicate that only low-molecular weight polymers dissolve in carbon dioxide and, as a result, only 10% to 20% increase in solution viscosity have been observed.
Other studies of the use of polymers for carbon dioxide thickening appear in "Measuring Solubility of Polymers in Dense CO.sub.2 " by J. P. Heller et al. (Polymer Preprint, Vol. 22(2), 1981, New York ACS Meeting) and "Direct Thickeners for Mobility Control of CO.sub.2 Floods" by J. P. Heller et al. (SPE 11789, June 1983). In the latter paper, Heller et al. conclude that the search for polymeric direct thickeners has been "unsuccessful in the purpose by a wide margin." The increase in viscosity observed by Heller et al. was small and in no case greater than 30%.
Recent work by J. P. Heller and J. J. Taber has been reported in "Development of Mobility Control Methods to Improve Oil Recovery by CO.sub.2 : Final Report," DOE/MC/10689-17 (available from NTIS) where the authors list some 53 polymers which have been tried in an effort to thicken the carbon dioxide but with little to no success.
Work done by Heller et al. was done with pure dry carbon dioxide at pressure of 1500 to 3160 psig and temperatures of 25.degree. to 58.degree. C. which would be typical of reservoirs where carbon dioxide flooding could be carried out. A number of low and high molecular weight polymers were tried, and in general their results showed that high molecular weight polymers were not soluble. Polymers having solubilities above one weight percent (i.e., polybutene, polydecene and polypropylene glycol) all had molecular weights of 400 to 1000. Increasing molecular weight of the polymer led to decreased solubility of the polymer in carbon dioxide. Heller's work suggests that it is not obvious how to find polymers having a molecular weight over 1000 that have any significant solubility in carbon dioxide. The known poor solvent properties of liquid and supercritical carbon dioxide are a limiting factor when it comes to dissolving large molecules such as high molecular weight polymers.
In our application entitled "ENHANCED OIL RECOVERY USING CO.sub.2 FLOODING", filed on July 14, 1987, and assigned U.S. Ser. No. 073,791, we taught a means to increase the viscosity of carbon dioxide to achieve a viscosity of at least 0.15 centipoises utilizing polymers having a molecular weight above 1000. We achieved viscosity increases for the carbon dioxide of three-fold to 30-fold or more utilizing certain defined cosolvents along with certain defined polymers having a minimum solubility parameter of 6.85 (cal/cc).sup.1/2 or less and having electron donor groups such as ether, silyl ether, and tertiary amine. Those defined polymers include polysiloxanes and polyvinylethers. Unfortunately, those polymers are expensive.